Most low pressure wells are found in matured and depleted petroleum fields. Completion may be damaged or collapsed. This restricts mechanical access to the lower portion of the well. Installation of a mechanical device at the lower portion may be impossible. This is particularly common deep in the well around the production packer. Completion may also have scale sediment limiting mechanical access with such a mechanical device. Many wells have in addition restrictions by design, such as nipples and other.
The type of the lower completion may be a cased and perforated slotted liner, an open hole, gravel packed, stand alone screen or any other type.
When performing pumping operations which increase the hydrostatic pressure in low pressure wells, loss of fluid to the formation may be experienced at full hydrostatic head conditions and even at much reduced head conditions in some cases. As the formation is unable to sustain the prevailing pressure, fluid may flow into the actual formation, in an uncontrolled manner. The challenge is well known from pumping operations for well cementing, scale treatment, water shut-off, well stimulation, and other similar activities.
In a low pressure well the top of the liquid phase in the well bore can be, for example, 500 meters below the well bore's surface. Thus the well bore from surface to 500 meters below the surface is filled with gas. The gas may be a hydrocarbon gas, air or a mixture of hydrocarbon gas and air. The gas may also be an inert gas such as N2. Gas is highly compressible when compared to liquid.
In such low pressure wells it is difficult to determine the location of a specific fluid stage pumped from the surface. This is because fluid in the well bore continues to flow downwards even after the pumping activity on the surface is terminated. The flow stops only when the pressure from the hydrostatic head is equal to the formation pressure. At this point, the upper section of the well may be full of highly compressible gas that makes controlled fluid displacement difficult. The specific fluid may end up anywhere in the well bore or in the formation, missing the targeted zone.
The problem is exemplified below by a cementing operation related to a Plug & Abandonment operation of a well. The example does not limit the scope of the invention.
According to prior art, a volume of cementing material is pumped into the well typically with a theoretical volume of displacement fluid above it, in order to locate the cementing material in the target zone of interest. However, in such a low pressure well, where the formation pressure is unable to sustain the hydrostatic head of the fluid column in the well, and where the resulting liquid head in the well bore at the end of the pumping operation is unknown, the cementing material can be under displaced or over displaced in an uncontrolled manner. Under such conditions, determining the required displacement fluid volume in order to displace the cementing material to a desired location is at least difficult.
Build up of scale is a problem in petroleum producing wells. Scale means any organic or non-organic deposit or any other undesired material on the production tubing or casing or in the formation. Scale may be dissolved in a suitable treatment fluid. A suitable treatment fluid may be an acid or a base. Removal of scale by treatment fluid requires a sufficient time of contact for the treatment fluid to dissolve the scale. Some of the treatment fluids used to remove scale may be aggressive or corrosive in nature. Therefore, it is not desirable to expose equipment such as wireline, valves, packers and anchors to such treatment fluids for too long.
Patent document U.S. Pat. No. 4,063,594 discloses a pressure-balanced well service valve for use in a low pressure formation. The valve is positioned at the bottom end of a tubing string, and the tubing string is provided with a packer above the valve. After the tubing string is located properly, the packer is set. Well fluid in the annulus below the packer may be circulated out upwards by opening a bypass valve in the packer and pumping treating fluid into the tubing. This displaces the well fluid up through the bypass valve into the annulus above the packer. The bypass valve in the packer is closed. The pressure on the treating fluid is continued and treating fluid is injected into a formation. After a calculated desirable amount of treating fluid has been injected into the formation, the pressure on the tubing is released and the service valve closes. After the treating fluid has been held in the formation the desired period, the treating fluid may be removed in the same manner as the well fluid as described above, by replacing the treatment fluid with another suitable fluid.